gas market outlook & lng business fundamentals
DESCRIPTION
An overview of global natural gas markets and the fundamentals of the LNG business, presented to the Legislative Budget and Audit Committee of the Alaska State Legislature on January 28, 2014TRANSCRIPT
http://enalytica.info
enalytica Data. Analytics. Solutions. in Energy
Prepared for the Alaska State Legislature Juneau, Alaska › January 28, 2014 !Janak Mayer, Partner › [email protected] Nikos Tsafos, Partner › [email protected]
Natural Gas Market Outlook & Fundamentals of LNG Business
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Gas and LNG Market Fundamentals are strong Gas makes up a rising share of the world’s energy mix
Demand for energy expected to rise by 1.2% a year through 2035, but gas grows faster at 1.6%
Gas supplies 23.7% of total energy in 2035 (vs. 21.3% in 2011)
Gas makes up 31% of growth in energy demand through 2035
LNG is the fastest growing part of the gas market
LNG demand has grown 4x faster than overall gas demand in last decade
LNG trade expected to grow by as much as 3.8% annually to 2030
Asia is the prize in terms of demand growth (75+% of total) and pricing
Multiple supply options create downward pressure on pricing — suppliers must compete
In gas pricing, micro (rather than macro) is still what matters
!2Executive Summarygas market outlook › LNG business fundamentals › implications for Alaska
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LNG Projects are Big, Complex and Multi-layered LNG projects take years (even decades) from first discovery to commercial production
They require a large capital commitment upfront—but deliver long-term revenue thereafter
No such thing as a “standard” project structure that Alaska can “adopt”
Complexity means that value creation and distribution is often a product of negotiation
States’ participation varies from not at all to fully involved throughout the value chain
LNG projects are often used to unlock stranded gas that is also supplied to local markets
LNG projects face many risks—but have established mechanisms for risk-management and mitigation
Third-party finance, marketing integration and pricing bands can reduce exposure/volatility
Price review clauses allow counter-parties to provide reprieve to grave imbalances
LNG projects tend to be partnerships between many private and state-owned enterprises
!3Executive Summarygas market outlook › LNG business fundamentals › implications for Alaska
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Alaska HAs Many Ways to Participate in LNG Project
!4
State’s Gas
gas in value: Key question is how to negotiate a “fair” transfer price
gas in Kind Agency marketing (Companies Sell gas on Alaska’s Behalf)
State markets Gas in-state Sales
FOB (Buyers Do Shipping)
CIF (Alaska Does Shipping)
equi
ty ac
ross
chai
n
Active engagement with project operationsstate taxes and regulates
Gas in value
Agency marketing or state markets gas
Executive Summarygas market outlook › LNG business fundamentals › implications for Alaska
Agency marketing or state markets gas
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‣ Natural gas market outlook ‣ fundamentals of LNG business ‣ Implications for Alaska ‣ Appendices
enalytica Data. Analytics. Solutions. in Energy
Energy demand has more than tripled since 1960 Oil provides 31% of total energy and is chiefly a transportation fuel
Coal provides 29%, chiefly for power; gas makes up 21.3% of total energy (of which 40% for power)
Nuclear and hydro provide a total of 7.5% all in power; biomass (10%) still large in residential use
!6
Energy Matrix in MMTOE (2011)
CoalOil &
ProductsNatural
GasNuclear Hydro
Biofuels & Waste
Other Total
Primary Supply 3,776.1 4,136.0 2,787.0 674.0 300.2 1,312.2 128.1 13,113.4
Power/Heat (2,365.6) (283.5) (1,118.2) (674.0) (300.2) (134.6) 2,143.5 (2,732.7)
Other Trnsfr 506.8 219.2 288.3 - - 65.8 383.1 1,463.2
Industry 728.9 323.2 506.4 - - 198.2 800.1 2,556.8
Transport 3.4 2,265.2 92.5 - - 58.6 25.2 2,444.9
Res/Comm/Agr 132.1 436.1 610.2 - - 855.0 1,063.1 3,096.4
Non-Energy 39.2 608.8 171.4 - - - - 819.4
% Total 28.8% 31.5% 21.3% 5.1% 2.3% 10.0% 1.0% 100%
Source: International energy agency, Key world Energy Statistics 2013
Energy › Gas › LNG › Gas Pricing › conclusionsenergy supply-demand matrix in 2011 › energy demand drivers › energy demand forecast
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Population Urbanization Real GDP GDP/capita Energy Use Energy Intensity
2010 2015 2020 2025 2030 2035
strong fundamentals support higher energy usE
!7
+0.9% p.a. +1.8 billion
+2.6% p.a. +90% Total
+1.25% p.a. non-oecd driven
-2.2% P.A. 43% Less Energy
51% › 61% +1.75 billion
+3.6% p.a. +240% Total
Source: UN Population Prospects (2012); UN, World Urbanization Prospects (2011) ; IEA, world Energy Outlook; OECD, Long-term GDP Projections (June 2013)
Energy › Gas › LNG › Gas Pricing › conclusionsenergy supply-demand matrix in 2011 › energy demand drivers › energy demand forecast
2x
1.5x
1x
0.5x
2.5x
2x
1.5x
1x
0.5x
2.5x
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IEA Forecasts Energy to Grow at 1.2% By 2035 Gas accounts for 31% of energy growth (1.6% annual growth); share of total energy from 21.3% to 23.7%
Coal plateaus in the 2020s and its share of total energy shrinks to 25.5% (vs. 28.8% in 2010)
Percent of fossil fuels declines from 81.6% in 2010 to 76% in 2035
!8Energy › Gas › LNG › Gas Pricing › conclusionsenergy supply-demand matrix in 2011 › energy demand drivers › energy demand forecast
0
2,000
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16,000
18,000
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2011 2020 2025 2030 2035
mmtoe
Energy Supply by Fuel
Coal Oil Gas Nuclear Hydro Biomass Other
Source: International energy agency, World Energy Outlook 2013 (November 2013)
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units › regional balances › trade corridors › gas demand forecast
gas units and conversions bbl barrel (oil) 1 bbl = 6 thousand cubic feet (6 mcf)
$/bbl dollars per barrel (oil) $6/bbl = $1/mcf ≃ $1/mmbtu
mmbtu million British thermal units $1/mmbtu ≃ $1/mcf
mmcf/d million cubic feet per day 1,000 mmcf/d = 7.8 mmtpa = 10.3 bcm/yr
bcf/d billion cubic feet per day 1 bcf/d = 7.8 mmtpa = 10.3 bcm/yr
bcm billion cubic meters 1 bcm/y = 0.73 mmtpa = 96.7 mmcf/d
mmtpa million tons per annum (LNG) 1 mmtpa = 1.37 bcm = 48.37 bcf/y = 132 mmcf/d
mmtoe million tons of oil equivalent 1 mmtoe = 1.11 bcm = 39.2 bcf = 107.4 mmcf/d
!9Energy › Gas › LNG › Gas Pricing › conclusions
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Only 30% of global gas Is traded (vs. 64% of Oil) Europe and Asia are deficit regions (71% of imports); FSU is the largest surplus region (26% of exports)
North America is the biggest producer (27% of global) and consumer (27% of global); it is in small deficit
68% of gas trade by pipeline; 32% as liquefied natural gas (LNG)
!10
Regional Balances (2012) in BCF/DProduction Exports Imports Net Demand
bcf/d % bcf/d % bcf/d % bcf/d bcf/d %N. America 86.5 27% 12.5 13% 13.6 14% -1.0 87.5 27%S. America 17.1 5% 4.0 4% 3.1 3% 0.9 15.9 5%
Europe 25.5 8% 19.9 20% 43.2 43% -23.3 48.0 15%FSU 74.4 23% 26.1 26% 8.9 9% 17.2 56.5 18%
Middle East 52.9 16% 15.4 15% 3.3 3% 12.1 39.7 12%Africa 20.9 6% 9.7 10% 0.6 1% 9.1 11.8 4%
Asia Pacific 47.3 15% 12.4 12% 27.3 27% -15.0 60.3 19%Total 324.6 100% 99.9 100% 99.9 100% 0.0 319.8 100%
units › regional balances › trade corridors › gas demand forecastEnergy › Gas › LNG › Gas Pricing › conclusions
Source: BP Statistical Review of World Energy (June 2013)
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Energy › Gas › LNG › Gas Pricing › conclusionsunits › regional balances › trade corridors › gas demand forecast
More than Half (58%) of gas trade within regions Intra-regional trade patterns
Intra-European trade accounts for 19.5% of the volumes traded internationally
Intra-North America and Intra-Asia Pacific make up another 12.5% each
Intra-FSU trade makes up 9% of total trade, mostly originating from Russia
Inter-regional trade patterns
Trade from FSU to Europe is the largest inter-regional trade route (13% of global)
Middle East and Africa into Europe almost as big (10.3% of global trade)
Middle East to Asia (9%) and FSU to Asia (3.5%) other major routes
Source: BP Statistical Review of World Energy (June 2013)
!11
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IEA puts Gas Demand Growth at 1.6% through 2035 OECD accounts for 18% of demand growth; non-OECD 82%
Asia accounts for 44% of incremental demand; Middle East follows by 19.5%
OECD North America grows faster than OECD Europe / OECD Asia due to cheaper gas prices
0
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2011 2020 2025 2030 2035
BCF/d
Gas Demand by Region
N. America Latin America Europe FSU Asia Mid East Africa
!12
units › regional balances › trade corridors › gas demand forecastEnergy › Gas › LNG › Gas Pricing › conclusions
Source: International energy agency, World Energy Outlook 2013 (November 2013)
326 bcf/d
481 bcf/d
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Energy › Gas › LNG › Gas Pricing › conclusionsregional overview › suppliers › consumers › demand outlook › supply outlook
LNG Market was 31.7 bcf/d in 2012 Middle East is largest surplus region (+12.3 bcf/d); Asia is largest deficit region (-11.5 bcf/d)
Around 70% of LNG went to Asia and 21% to Europe
South America and Middle East are recent importers (since 2008); they took in 6% of demand in 2012
Middle East (40%) and Asia Pacific (33.2%) were the largest suppliers of LNG
Africa is the next largest supplier (Algeria, Nigeria, Eq. Guinea, Egypt) with 16.5% of exports
Source: BP Statistical Review of World Energy (June 2013)
LNG Imports and Exports in 2012Imports Exports Net
bcf/d % Total bcf/d % Total bcf/dMiddle East 0.4 1.4% 12.7 40.1% 12.3
Africa 0.0 0.0% 5.2 16.5% 5.2S. & C. America 1.5 4.6% 2.4 7.6% 0.9
N. America 1.1 3.5% 0.1 0.2% -1.0Europe 6.7 21.1% 0.8 2.4% -5.9
Asia Pacific 22.0 69.3% 10.5 33.2% -11.5Total 31.7 100% 31.7 100% 0.0
!13
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Source: international gas union, World LNG Report 2013 (June 2013)
Qatar is by far Largest LNG Exporter (32.6% Total) Five countries (Qatar, Malaysia, Australia, Nigeria, Indonesia, Trinidad) make up 73% of supply
Russia, Peru, and Yemen have all started to export after 2008. Angola started exports in 2013
32.6%
9.7% 8.7% 8.4% 7.6% 6.1%
4.6% 4.6% 3.4% 2.9% 2.3% 2.2% 2.1% 1.6% 1.6% 1.4% 0.1%
0%
5%
10%
15%
20%
25%
30%
35%
0
10
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Qata
r
Mala
ysia
Aust
ralia
Nige
ria
Indo
nesia
Trin
idad
Alge
ria
Russ
ia
Oman
Brun
ei
UAE
Yeme
n
Egyp
t
Peru
Eq. G
uine
a
Norw
ay
USA
% Total mmtons LNG Exports (2012)
!14Energy › Gas › LNG › Gas Pricing › conclusionsregional overview › suppliers › consumers › demand outlook › supply outlook
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Source: international gas union, World LNG Report 2013 (June 2013)
LNG Demand concentrated among few buyers Two markets (Japan and Korea) account for 50% of demand
Six countries (Japan, Korea, China, Spain, India, Taiwan) make up 75% of demand
15 countries import less than 2% of global demand each — but more and more countries importing LNG
36.7%
15.5%
6.2% 6.0% 5.9% 5.4% 4.4% 3.1% 2.4% 2.2% 1.6% 1.5% 1.4% 1.3% 1.1% 0.9% 0.8% 0.7% 0.5% 0.5% 0.5% 0.4% 0.4% 0.4% 0%
5%
10%
15%
20%
25%
30%
35%
40%
0 10 20 30 40 50 60 70 80 90
100
Japa
n
Kore
a
Chin
a
Spai
n
Indi
a
Taiw
an
UK
Fran
ce
Turk
ey
Italy
Arge
ntin
a
Mexi
co
USA
Chile
Braz
il
Kuwa
it
Belg
ium
Port
ugal
Cana
da
UAE
Gree
ce
Thai
land
Puer
to Ri
co
Dom.
Rep.
% Total mmtons LNG Imports (2012)
!15Energy › Gas › LNG › Gas Pricing › conclusionsregional overview › suppliers › consumers › demand outlook › supply outlook
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LNG demand to grow 3.8% a year to 2030 Asia has been and remains the dominant market for LNG and accounts for 75+% of demand growth
Demand for LNG in Americas flat; shale shrinks N. America’s needs but S. America grows
Europe flat through 2020 but growth thereafter driven by resource maturity
Middle East and Africa fastest growing markets but volumetrically make bigger impact post 2020
!16
LNG Imports in MMTPA
2010 2015 2020 2030 Δ: 10-30 Δ: 10-30
Americas 21 20 16 19 -2 -0.3%
Europe 64 28 60 98 34 6.5%
Mid East/Africa 3 6 10 38 35 9.7%
Asia 129 200 256 377 248 3.2%
Total 217 254 342 532 315 3.8%
Source: Wood Mackenzie LNG Forecast (Data from Cheniere IR Presentation in January 2014)
Energy › Gas › LNG › Gas Pricing › conclusionsregional overview › suppliers › consumers › demand outlook › supply outlook
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Many possible Suppliers, Many Risks to manage
!17
Ample possible Shale Gas but need for infrastructure and commercial viability
Cheap Gas, but Slow permitting process and possible Price
volatility
Much Associated gas But local markets take priority
Large Scale Resources But technical risks
Much Associated gaS but local markets take priority
Qatar / Iran huge resource; local markets
priority, Economics, politics
Sizable remaining resources but exorbitant costs
Sizable undeveloped gas But Local market take
priority
Sizable stranded gas but high costs
Over 30 tcf but significant political risks
Over 100 tcf But high cost of entry, low government capacity, High
infrastructure needs
Over 34 tcf in north slope but Uncertain Fiscal terms/
project economics
Energy › Gas › LNG › Gas Pricing › conclusionsregional overview › suppliers › consumers › demand outlook › supply outlook
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pricing structures › regional spreads › intra-region spreads › intra-country spreads › outlook
GAs Pricing structures highly variable Gas pricing can be either cost-plus or market netback
Gas is usually priced in any of four alternative ways; some deals could include a mixture of all four
!18
Market-Based (Hubs) Pricing references a marker; e.g. Henry Hub in the United States or National Balancing Point (NBP) in the United Kingdom
Alternative Fuels (e.g. Oil, Oil Products, Coal)
Pricing references a competing fuel to retain competitiveness of gas; e.g. LNG into Japan priced against Japan Customs Cleared (JCC) price; pipe gas in Europe vs. HFO/diesel
end-products (e.g. electricity, chemicals)
Pricing references a final product price; e.g. EOG in Trinidad sells gas to local consumers at a price linked to exported methanol/ammonia
FLAT RATEThe price negotiated does not reference any external marker, except perhaps inflation; e.g. The Alba gas field in Equatorial Guinea sells to the LNG and a methanol plant at a flat rate
Energy › Gas › LNG › Gas Pricing › conclusions
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Energy › Gas › LNG › Gas Pricing › conclusionspricing structures › regional spreads › intra-region spreads › intra-country spreads › outlook
No Such Thing as a “Global Gas” Price There has always been a major disparity between regional prices
In 2012, Henry Hub in the United States averaged $2.76/MMBtu; the price in Japan was $16.75/MMBtu
European pricing was somewhere in the middle: $9.46/MMBtu in the UK to $11.03/MMBtu in Germany
!
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2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
$/MMBtu Gas Prices in Select Markets
Source: BP Statistical Review of World Energy (June 2013)
Japan
United States
Germany
UK
!19
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Gas Prices in Select Markets
pricing structures › regional spreads › intra-region spreads › intra-country spreads › outlook
No Such Thing even as an “Asian” Gas Price LNG prices in Asia ranged from $17.81/mcf on average in Japan to $11.52/mcf on average in China
China and India have cheaper average prices due to some lower priced contracts signed in early 2000s
From 2003 to 2008, Japan had lower prices than Korea and Taiwan; since 2010, it has had higher prices
Source: National Statistical Agencies, UN Comtrade, BP Statistical Review of World Energy (June 2013)
Japan
China
Korea
India
Taiwan
!20Energy › Gas › LNG › Gas Pricing › conclusions
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0
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$/mcf
billion cubic feet / Day
Korea LNG Supply Curve (2013)
pricing can vary even within countries For example, Korea paid $15.88/mcf for LNG in 2013
But bilateral prices ranged from $19.25/mcf (Norway) to $6.40/mcf (Russia)
Individual contract terms can matter more than the destination country in general
pricing structures › regional spreads › intra-region spreads › intra-country spreads › outlook
Source: Korea International Trade Association (KITA), http://Kita.org (Accessed January 2014)
Qatar
MalaysiaIndonesia
Oman
Russ
ia
Brun
eiYemen
!21Energy › Gas › LNG › Gas Pricing › conclusions
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pricing structures › regional spreads › intra-region spreads › intra-country spreads › outlook
Gas Pricing is Undergoing Fundamental Changes Gas pricing tends to go through cycles
Surplus: prices tend to fall to the marginal cost of supply (cost-plus): $8-12/MMBtu
Shortage: prices move to cost of alternative fuels or demand destruction (netback): $16-18/MMBtu
Timing is everything — but pricing formulae can change
Current market conditions pushing pricing towards cost-plus (e.g. US Gulf Coast)
LNG pricing post 2020 will be driven by:
How quickly will proposed projects move forward (turning possible supply into real supply)?
The strategies of importers: will they create new supply and not renew old contracts?
How will existing suppliers (e.g. Qatar) respond? Will they try to undercut new suppliers?
How quickly will gas hubs develop (e.g. Singapore, Tokyo)?
!22Energy › Gas › LNG › Gas Pricing › conclusions
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Energy › Gas › LNG › Gas Pricing › conclusions
Gas and LNG Market Fundamentals are strong Gas makes up a rising share of the world’s energy mix
Demand for energy expected to rise by 1.2% a year through 2035, but gas grows faster at 1.6%
Gas supplies 23.7% of total energy in 2035 (vs. 21.3% in 2011)
Gas makes up 31% of growth in energy demand through 2035
LNG is the fastest growing part of the gas market
LNG demand has grown 4x faster than overall gas demand in last decade
LNG trade expected to grow by as much as 3.8% annually to 2030
Asia is the prize in terms of demand growth (75+% of total) and pricing
Multiple supply options create downward pressure on pricing — suppliers must compete
In gas pricing, micro (rather than macro) is still what matters
!23
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‣ Natural gas market outlook ‣ Fundamentals of LNG Business ‣ Implications for Alaska ‣ Appendices
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Big, Upfront investment, Long-term revenue LNG projects take 4-5 years to build but run for 20-50 years with low maintenance / upkeep costs
Majority of LNG projects have been expanded and/or taken gas from new fields
Subpar rate of return tends to be bigger risk than outright “losing money”
!25Basics › structures › development risks › operations › Risk mitigation › conclusionseconomic rationale › milestones › LNG sales and purchase agreements (SPAs) › domestic gas allocation
-6
-4
-2
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US$ billion
years
LNG Plant Cash Flow: Typical Plant
CAPEX Liquefaction OPEX Upstream OPEX Revenue Government Take Cash Flow
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LNG projects move on many parallel fronts Upstream Delineate resource base, certify reserves, define production plan
Midstream Define pipeline path, secure right-of-way, environmental permits
Liquefaction Define project size, processing / gas quality, project structure
Shipping Decide whether to own, lease or outsource shipping to buyers
Marketing Define commercialization plan, secure buyers, sign contracts
Financing Define financing plan, secure in-house and third-party lending
Permitting Secure permits to construct facility, export gas
Partners conduct front-end engineering and design studies (pre-FEED and FEED)
They then sign engineering, procurement and construction (EPC) contracts
Construction starts with final investment decision (FID); usually less than 10% of CAPEX spent before FID
!26Basics › structures › development risks › operations › Risk mitigation › conclusionseconomic rationale › milestones › LNG sales and purchase agreements (SPAs) › domestic gas allocation
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Pricing Pricing will refer to some alternative fuel (usually crude oil or oil products) and/or a gas marker (e.g. Henry Hub, NBP in the United Kingdom, etc.)
Duration & Start For new projects, contracts are usually 15-20 years. Contracts will also specific start date (month / year)
Destination clauses
Destination clauses, which restrict which markets the LNG can be sold at, are increasingly out of favor—and are illegal in Europe. However, producers dislike when their gas is resold to third parties without any upside to them. LNG in Atlantic Basin is generally destination-free, Qatari equity marketed gas is flexible, and Pacific LNG has territorial restrictions.
Volume quantity & Flexibility
Contracts are typically take-or-pay: buyers can typically buy 10-20% more or less of their annual take-or-pay volumes—but they have to pay for LNG whether they lift it or not.
Schedule & Logistics Estimated schedule for delivering cargoes (e.g. seasonality patterns) and logistics for delivery (e.g. tanker size)
Gas Quality Specifications for gas, including any treatment of liquids
Profit Sharing Some contracts allow the original seller to share the profit in case a cargo is diverted from its original source, but such provisions are illegal in Europe (they are considered to inhibit competition)
Non-Compliance Penalties can involve non-delivery, delays, off-spec gas (different gas quality)
Renegotiation Most contracts will allow price reviews every 3-4 years but usually within a band. Most contracts will also allow a one-time review clauses for extraordinary circumstances. Arbitration is usually required when parties cannot agree
Title Transfer Specification of when the LNG transfers ownership from buyer to seller (e.g. FOB, CIF, DES)
!27Basics › structures › development risks › operations › Risk mitigation › conclusionseconomic rationale › milestones › LNG sales and purchase agreements (SPAs) › domestic gas allocation
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LNG exports Often linked to Domestic Gas sales LNG projects could either seek to scale up existing producing assets or may unlock stranded gas
In cases where there is no existing production, LNG exports often serve as foundation for a local market
The prospect of exports often incentivizes further exploration that benefits local and export markets
Some jurisdictions (Indonesia, Western Australia) have explicit domestic gas reservation policies
!
Examples Angola LNG will deliver 125 mmcf/d to the local market Bintulu LNG (Malaysia) makes possible gas consumption in the remote areas of Sarawak (east Malaysia) Donggi Senoro LNG (Indonesia) will couple exports with sales to local ammonia and power plants North West Shelf (Australia) started to supply local market 5 years before exports started (1984 / 1989) Yemen LNG sources gas from gas Marib Area—1 tcf of 9.15 has been allocated to local market
!28
Sources: Company press releases and Industry Press
Basics › structures › development risks › operations › Risk mitigation › conclusionseconomic rationale › milestones › LNG sales and purchase agreements (SPAs) › domestic gas allocation
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Integrated Projects distribute Value Internally Same companies own upstream and midstream—value driven by sales price (FOB/CIF)
Distribution of value between upstream and midstream is an internal transfer question
Transfer price may or may not be public
!29Basics › structures › development risks › operations › Risk mitigation › conclusionsintegrated › merchant › tolling › trade-offs › state participation
Upstream Liquefaction Sales
Gas produced across Algeria Piped to shore
Sonatrach 100% owned facilities FOB: $11.50/mcf
Various LNG SPAs & direct marketing
Gas produced from the North Field Varying ownerships
Qatargas & RasGas Varying ownerships
FOB: $11.36/mcf
LNG pricing ranging from China: $20
North America >$3
Gas produced and piped across Sakhalin Island
(500 miles of pipe)
Sakhalin-2 LNG project Both trains same ownership
FOB: $6.18/mcf
Various SPAs Japan (76%): $15.40 Korea (20%): $8.10
Alge
ria
Qata
r
Source: Company financial reports and country import statistics
Russ
ia
Internal Transaction | Third-Party Transaction
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Infrastructure owner drives pricing Infrastructure owner buys gas and sells LNG—value in differential between upstream and downstream
FOB price does not need to be linked to upstream price (e.g. Equatorial Guinea)
Upstream price can be netback (e.g. Malaysia LNG) or cost-plus (e.g. Sabine Pass)
!30Basics › structures › development risks › operations › Risk mitigation › conclusionsintegrated › merchant › tolling › trade-offs › state participation
Upstream Liquefaction Sales
Noble Energy: Alba Field 235 mmcf/d (2012)
% sold to LNG $0.25/MMBtu
Marathon-Operated: EG LNG T1 90% * Henry Hub linked
FOB price: $2.57 FOB cost: under $1
BG Group LNG Sales to Japan (76%): $18.65 Korea (10%): $15.04
Taiwan: (5%): $20.38
Murphy Oil: SK 309 and SK 311 174 mmcf/d (2012)
50% * LNG export price $7.50/mcf
PETRONAS: Malaysia LNG Oil-linked pricing
Various contracts (mostly cif) FOB: $15.64
LNG Sales to Japan (62%): $19.07 Korea (18%): $11.69
Taiwan: (12%): $19.11
No single supplier Gas sourced from the market
Henry Hub prompt month in 2013 $3.73/MMBtu
Cheniere Energy: Sabine Pass 16-18 mmtpa
115% * Henry Hub + $2.25 to $3 FOB: $6.54 to $7.29
LNG SPAs BG Group, Gas Natural Fenosa
GAIL, KOGAS Companies can resell LNG for any price
Eq. G
uine
aMa
lays
ia
Source: Company financial reports and country import statistics
Sabi
ne Pa
ss
Internal Transaction | Third-Party Transaction
enalytica Data. Analytics. Solutions. in Energy
LNG Akin to Pipeline: Pay a Fee to use Facility In a tolling structure, the supplier or buys pays the liquefaction owner a usage fee
The infrastructure owner takes no ownership of the gas
The relevant pricing is between supplier and buyer; infrastructure owner is “irrelevant”
!31Basics › structures › development risks › operations › Risk mitigation › conclusionsintegrated › merchant › tolling › trade-offs › state participation
Upstream Liquefaction Sales
BG Group (50%) and PETRONAS (50%) West Delta Deep Marine
Conduct SPAs with off-takers Pay liquefaction plant a fee
T1: BG 35.5%, PETRONAS 35.5% EGPC 12% EGAS 12%, GDF SUEZ 5%
T2: BG 38%, PETRONAS 38% EGPC 12% EGAS 12%
!
Train 1 sales 100% to GDF SUEZ Train 2 sales 100% to BG Group
Various suppliers e.g. BG and partners 28.9% of gas supply
Pay liquefaction plant a fee (est. $1/mcf) Upstream pricing is netback from FOB
T4 : BP 38%, BG 29%, Shell 22%, NGC 11%
FOB price (est. $5.16/mcf)
Off-take proportional to gas supply Some suppliers may sell gas FOB
Henry Hub pricing and profit sharing e.g. Japan ($13.63/mcf)
No single supplier Gas sourced from the market
Sempra 50.2% Mitsubishi 16.6%
Mitsui 16.6% GDF SUEZ 16.6%
Mitsubishi, Mitsui and GDF SUEZ Pay LNG facility a tolling fee
They also procure their own gas
Egyp
tian
LNG
Trin
idad
Source: Company financial reports and country import statistics
Came
ron
Internal Transaction | Third-Party Transaction
enalytica Data. Analytics. Solutions. in Energy
There is No “Right” Project Structure Type of resource base is often a major driver (size of initial resource, expansion potential, new fields)
The partners risk appetite and desire to commit capital is another main driver
Expansion prospects and competitive landscape is a third driver (# of companies that could supply gas)
!32Basics › structures › development risks › operations › Risk mitigation › conclusionsintegrated › merchant › tolling › trade-offs › state participation
Advantages Disadvantages
IntegratedIntegrated plants are simple—the only relevant point is the sales price to the off-take
Integrated projects work when there is high partner alignment, a steady (not variable) source of gas and where all partners are equally interested in any expansions
MerchantProject can accommodate new supply sources. Especially useful to allow companies varying participation along the chain and to enable projects to tap new resources
Multiple transaction points can cause tensions and/or delays in the project.
TollingVery adaptable and able to accomodate changes in upstream supply. Easily scalable.
Setting tolling fee can be a challenge, particularly in cases where the upstream players have a bias towards using their own supplies
enalytica Data. Analytics. Solutions. in Energy
State Participation in LNG Projects varies Greatly Several states take no equity stake in LNG projects—they merely regulate and tax
Most countries have some equity—but their involvement varies from passive to very active
Equity stakes are held through national oil companies—Brunei and Norway (Petoro) are exceptions
!33Basics › structures › development risks › operations › Risk mitigation › conclusionsintegrated › merchant › tolling › trade-offs › state participation
Source: Ownership from GIIGNL, The LNG Industry in 2012, http://www.giignl.org/sites/default/files/publication/giignl_the_lng_industry_2012.pdf
Australia, Canada, Indonesia (Tangguh), Peru, Russia (Yamal), USA
Algeria, Malaysia, Qatar
Russia (Sakhalin-2), Indonesia (Bontang) Norway
equi
ty ac
ross
chai
n
Active engagement with project operationsstate taxes and regulates
Abu Dhabi Oman Trinidad
Angola Brunei Nigeria
Eq. Guinea Egypt Yemen
enalytica Data. Analytics. Solutions. in Energy
LNG Takes Time, often decades from First Discovery LNG projects are big, complex, multi-stakeholder agreements and they often take years to put together
Challenges include offtake, capital, permits, partner commitment, or overcoming technical problems
Several existing projects were stuck for a long-period of time in the planning phase
!
Examples The Camisea complex (Peru) discovered in early 1980s, online in 2004 and exported LNG in 2010 The Gorgon gas field (Australia) discovered in 1981 with LNG exports starting in 2015 North Field (Qatar) was discovered in 1971, but LNG exports started in 1996 Shtokman (Russia) discovered in 1988, but still lacks a development path Snøhvit (Norway) was discovered in 1984 and LNG started in 2007 Atlantic LNG (Trinidad) project first mulled in 1970s, then again early 1980s; first LNG started in 1999
!34Basics › structures › development risks › operations › Risk mitigation › conclusionsdelays to sanction project › partner drag › delays and cost overruns
Sources: Company press releases and Industry Press; ViktoR, et. Al, “Natural Gas and Geopolitics”
enalytica Data. Analytics. Solutions. in Energy
Partner alignment crucial for LNG Development Many LNG projects were developed by a different set of companies that first proposed the LNG project
Partners with low portfolio fit and/or risk appetite can slow down project development
Getting new partners is often a precondition for an LNG project to move forward
!
Examples ExxonMobil pulled out of Angola LNG; Eni acquired stake soon thereafter Atlantic LNG (Trinidad) T2-3 needed new shareholding deal as Cabot and NGC did not want to participate Kitimat LNG (Canada) started off as Apache/EOG, then EnCana joined; now Chevron / Apache (50:50) PTT (Thailand) acquired Cove Energy to access gas that could supply an LNG project in Mozambique North Field (Qatar) discovered by Shell; Shell and later BP left; LNG developed by Mobil (now ExxonMobil) Marathon and McDermott sold out of Sakhalin Energy (Sakhalin-2 LNG in Russia)
!35Basics › structures › development risks › operations › Risk mitigation › conclusionsdelays to sanction project › partner drag › delays and cost overruns
Sources: Company press releases and Industry Press; ViktoR, et. Al, “Natural Gas and Geopolitics”
enalytica Data. Analytics. Solutions. in Energy
!36Basics › structures › development risks › operations › Risk mitigation › conclusionsdelays to sanction project › partner drag › delays and cost overruns
Project Sanctioned Target Date Actual Date DElay Budget BN Cost BN % Overrun
Snøhvit (Norway) Mar-02 2006 Sep-07 1.5 years NOK39.50 NOK48.00 21.5%Egyptian LNG T1 Sep-02 Aug-05 May-05 3 months early $1.1 on budget 0%Sakhalin-2 (Russia) May-03 2007 Mar-09 2 years $10.0 $22.0 120.0%Atlantic LNG T4 (Trinidad) Jun-03 2005 Dec-05 on time $1.2 on budget 0%Egyptian LNG T2 Jul-03 Jun-06 Sep-05 9 months early $0.6 on budget 0%Equatorial Guinea Jun-04 Late 2007 May-07 6 months early $1.5 on budget 0%North West Shelf (Australia) Jun-05 2008 Sep-08 on time AUS$2 AUS$2.6 30.0%Yemen Aug-05 Dec-08 Nov-09 1 year $3.7 $4.5 21.6%Peru Jan-07 mid 2010 Jun-10 on time $3.8 $3.9 2.6%Pluto Jun-07 Early 2011 May-12 1.5 years AUS$11.2 AUS$14.9 33.0%Skikda LNG (Algeria) Jun-07 2011 Mar-13 2 years $2.8 ? ?Angola Dec-07 Early 2012 Jun-13 1.5-2 years ? $10.0 ?Gorgon (Australia) Sep-09 2014 n/a n/a $37.0 $54.0 45.9%Papua New Guinea Dec-09 2014 n/a n/a $15.0 $19.0 26.7%Queensland Curtis (Australia) Nov-10 2014 n/a n/a $15.0 $20.5 36.7%Gladstone LNG (Autralia) Jan-12 2015 n/a n/a $16.0 $18.5 15.6%
Source: Company press releases and Industry Press
enalytica Data. Analytics. Solutions. in Energy
0
100
200
300
400
500
600
700
Sep-07 Mar-08 Sep-08 Mar-09 Sep-09 Mar-10 Sep-10 Mar-11 Sep-11 Mar-12 Sep-12 Mar-13 Sep-13
MMCf/d Snøhvit LNG Plant (Norway): GAs Production
Technical challenges can lead to frequent outages Historically, the LNG industry has operated plants at high utilization rates (85-90%)
However, as projects become more technically complex, outages are a real risk
For example, Snøhvit (Norway) has experienced frequent outages (2-3 months) since start-up in 2007
!37
Outa
ges
Outa
ges
Outa
ges
Basics › structures › development risks › operations › Risk mitigation › conclusionsoutages › domestic gas diversion › natural decline › demand shock: volume › demand shock: price
Source: Norwegian petroleum Directorate, Factpages, Production Monthly by Field (Accessed January 2014)
enalytica Data. Analytics. Solutions. in Energy
supplying local markets can divert gas from LNG Indonesia has seen exports from its oldest facilities (Arun and Bontang) decline over time
At issue is a combination of resource depletion and a need to divert gas to local markets
Arun has been shut down and is being converted to an import terminal
!38
Sources: Pengkajian Energi Universitas Indonesia, Indonesia Energy Outlook & Statistics 2006, Ministry of Energy and Natural Resources, “Statistik Gas Bumi 2012”
Basics › structures › development risks › operations › Risk mitigation › conclusionsoutages › domestic gas diversion › natural decline › demand shock: volume › demand shock: price
2.81
3.15 3.26
3.04 3.01 3.05 3.03 2.96 2.81 2.80
2.67 2.54
2.24
1.62 1.75
1.03
0.46
0.95 0.97 0.87 0.65
0.53 0.44 0.40 0.34 0.30 0.18 0.14
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
bCf/d
Arun and Bontang LNG Plants (Indonesia): GAs Exports
Bontang Arun
enalytica Data. Analytics. Solutions. in Energy
Feedstock Maturity Can Lead to Rapid Decline Kenai was the second LNG project in the world and it supplied Japan continuously since 1969
As production matured, however, exports faced a precipitous decline: from 2007 to 2012 fell 25% a year
Matching the production profile to LNG sales contracts is essential to mitigate any penalties
!39
Source: US Energy Information Administration,Alaska Liquefied Natural Gas Exports to Japan (Accessed January 2014)
Basics › structures › development risks › operations › Risk mitigation › conclusionsoutages › domestic gas diversion › natural decline › demand shock: volume › demand shock: price
178
26
0
20
40
60
80
100
120
140
160
180
200
1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009 2011
MMCf/d
LNG Exports from Alaska to Japan
enalytica Data. Analytics. Solutions. in Energy
Demand Shock led to output losses— But long ago Algeria experienced two waves of LNG output contraction in the 1980s and early 1990s
Both were driven by declines in demand for Algerian LNG from the United States (and, less so, France)
But the depth of the current LNG market has meant that producers face price but not output risk
!
For example, Snøhvit (Norway) has experienced frequent outages since coming online in 2007
!40
Sources: US Energy Information Administration,U.S. LNG Imports From Algeria (Accessed January 2014), Ministère de l’Energie et des Mines, Energy Balance 1980-2004
Basics › structures › development risks › operations › Risk mitigation › conclusionsoutages › domestic gas diversion › natural decline › demand shock: volume › demand shock: price
235 101 151
359
99 65 - - 48 116 231 174 118
224 139
49
644 743
1,003
1,548
1,198 1,250 1,222 1,382
1,485
1,709 1,872 1,903 1,948 2,002
1,800 1,768
0
500
1,000
1,500
2,000
2,500
1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995
mmcf/d
LNG Exports from Algeria USA Total
enalytica Data. Analytics. Solutions. in Energy
0
5
10
15
20
25
0 1 2 3 4 5 6 7 8 9 10
$/mcf
billion cubic feet / Day
Qatar: LNG Price Curve (2012) (markets Accounting for 89% of total sales)
Price Risk More Important than Volume Risk Market fundamentals affect price rather than volume (2012 utilization was over 100%)
Qatar earns vastly different prices across markets: $20/mcf in China to sub-$3/mcf in North America
Lower prices reflect contracts linked to low benchmarks (e.g. Belgium) or LNG “pushed into” markets
!41
Sources: international gas union, World LNG Report 2013 (June 2013), UN Comtrade Database (Accessed January 2014)
Basics › structures › development risks › operations › Risk mitigation › conclusionsoutages › domestic gas diversion › natural decline › demand shock: volume › demand shock: price
Korea JapanIta
ly
India
United Kingdom
Chin
a
enalytica Data. Analytics. Solutions. in Energy
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
% LNG Sold to Partners
% LNG Capacity
PErcent Of LNG Capacity Sold to Equity Partners Projects Online in 2012
Buyers Often Take Equity | Partners off-take LNG In half of the world’s LNG capacity, a share of the LNG is sold to equity partners
Such deals can mitigate risk by aligning supplier-buyer interests (e.g. output shortfall)
Buyers get sense of supply security, and these deals often open up the project to third-party financing
!42
buyers have no Equity
Share of LNG Sold to Partners
Partners take all the LNG
Source: Based on GIIGNL, The LNG Industry in 2012, http://www.giignl.org/sites/default/files/publication/giignl_the_lng_industry_2012.pdf
Basics › structures › development risks › operations › Risk mitigation › conclusionsmarketing integration › third-party financing › pricing bands › renegotiation
enalytica Data. Analytics. Solutions. in Energy
!43Basics › structures › development risks › operations › Risk mitigation › conclusionsmarketing integration › third-party financing › pricing bands › renegotiation
Project Finance well established in LNG IHS estimates that LNG projects raised over $97 billion in third-party financing since 2000
Financing from project sponsors, export credit agencies, multilateral banks and commercial banks
Commercial loans can also secure sovereign guarantees as insurance
The Japan Bank of International Cooperation (JBIC) is the largest single provider of funds
Examples AP LNG $5.8 billion US EXIM, China EXIM, banks Ichthys $20 billion JBIC, Korea and Australia EXIM, banks, sponsors ($4 bn) Papua New Guinea $14 billion Six ECAs and 17 banks, ExxonMobil Peru $2.25 billion IADB, US EXIM, Korea EXIM, IFC, others Sakhalin-2 $6.4 billion JBIC, NEXI, banks Tangguh $3.5 billion JBIC, ADB, banks
Sources: IHS in Ledesma, et. Al, “The Commercial and Financing Challenges of an Increasingly Complex LNG Chain,” LNG 17 (April 2013); Industry press
enalytica Data. Analytics. Solutions. in Energy
Pricing formula can reduce price volatility “S-curves” are clauses that change the relationship between oil and gas above or below thresholds
Instead of a linear link, gas prices do not rise/fall as much if oil prices rise/fall above certain thresholds
They reduce downside risk by forgoing some upside—they can even provide a floor/ceiling on prices
!
!
!
!
!
Basics › structures › development risks › operations › Risk mitigation › conclusionsmarketing integration › third-party financing › pricing bands › renegotiation
Oil or other reference Price
LNG S
ales
Pric
e
No S-Curve S-Curve Floor / ceiling
!44
enalytica Data. Analytics. Solutions. in Energy
Worst case, there is always renegotiation Most LNG contracts include price review clauses—especially for fundamental / unforeseen changes
Most renegotiations focus on pricing—but European disputes have included volumes (take-or-pay)
Disputes between states and companies usually center on upside that is not flowing back to the state
!
Examples BG and its Chilean buyers renegotiated to raise LNG prices
Brunei and Japanese buyers adjusted their price formula—as a result prices tripled from 2007 to 2008
Gas Natural and Atlantic LNG went to arbitration and add a US-based reference price to their contract
RasGas gave a price discount to Edison (Italy) after arbitration settlement ($580 mm in 2012)
Yemen LNG increased its LNG sales prices towards GDF SUEZ, TOTAL, KOGAS
!45Basics › structures › development risks › operations › Risk mitigation › conclusionsmarketing integration › third-party financing › pricing bands › renegotiation
Sources: Company press releases and Industry Press
enalytica Data. Analytics. Solutions. in Energy
LNG Projects are Big, Complex and Multi-layered LNG projects take years (even decades) from first discovery to commercial production
They require a large capital commitment upfront—but deliver long-term revenue thereafter
No such thing as a “standard” project structure that Alaska can “adopt”
Complexity means that value creation and distribution is often a product of negotiation
States’ participation varies from not at all to fully involved throughout the value chain
LNG projects are often used to unlock stranded gas that is also supplied to local markets
LNG projects face many risks—but have established mechanisms for risk-management and mitigation
Third-party finance, marketing integration and pricing bands can reduce exposure/volatility
Price review clauses allow counter-parties to provide reprieve to grave imbalances
LNG projects tend to be partnerships between many private and state-owned enterprises
!46Basics › structures › development risks › operations › Risk mitigation › conclusions
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‣ Natural gas market outlook ‣ fundamentals of LNG Business ‣ Implications for Alaska ‣ Appendices
enalytica Data. Analytics. Solutions. in Energy
path forward requires answers to Key Questions How should Alaska take its gas share?
Should the state take equity in the project and if so, in what parts of the value chain?
If the state decides to take its gas entitlement in kind, how will it market that gas?
What is the state’s appetite for risk, and what type of risk?
What type of risk mitigators will make the state more comfortable about participating in an LNG project?
Is the state prepared to forgo some upside in order to be better protected on the downside?
What project structure can expedite development while allowing the project to evolve with time?
What are the state’s long-run revenue needs and how might the LNG project help meet those needs?
!48Implications for Alaskakey questions › decision matrix
enalytica Data. Analytics. Solutions. in Energy
Alaska HAs Many Ways to Participate in LNG Project
!49
State’s Gas
gas in value: Key question is how to negotiate a “fair” transfer price
gas in Kind Agency marketing (Companies Sell gas on Alaska’s Behalf)
State markets Gas
Implications for Alaska
in-state Sales
FOB (Buyers Do Shipping)
CIF (Alaska Does Shipping)
equi
ty ac
ross
chai
n
Active engagement with project operationsstate taxes and regulates
Gas in value
Agency marketing or state markets gas
key questions › decision matrix
Agency marketing or state markets gas
enalytica Data. Analytics. Solutions. in Energyenalytica Data. Analytics. Solutions. in Energy
‣ Natural gas market outlook ‣ fundamentals of LNG Business ‣ implications for Alaska ‣ Appendices
enalytica Data. Analytics. Solutions. in Energy
Our Team
Before co-founding enalytica, Janak led the Upstream Analytics team at PFC Energy, focusing on fiscal terms analysis and project economic and financial evaluation, data management and data visualization.
Janak has modeled upstream fiscal terms in all of the world’s major hydrocarbon regions, and has built economic and financial models to value prospective acquisition targets and develop strategic portfolio options for a wide range of international and national oil company clients. He has advised Alaska State Legislature for multiple years on reform of oil and gas taxation, providing many hours of expert testimony to Alaska’s Senate and House Finance and Resources Committees.
Prior to his work as an energy consultant, Janak advised major minerals industry clients on a range of controversial environmental and social risk issues, from uranium mining through to human rights and climate change. He has advised bankers at Citigroup and policy-makers at the US Treasury Department on the management and mitigation of environmental and social impacts in major projects around the world, and has undertaken macroeconomic research with senior development economists at the World Bank and the Peterson Institute for International Economics.
Janak holds an MA with distinction in international relations and economics from from the Johns Hopkins School of Advanced International Studies (SAIS), and a BA with first-class honors from the University of Adelaide, Australia.
!51
Janak Mayer › Nikos Tsafos
Janak Mayer Partner
!!
enalytica
enalytica
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Our Team
Nikos Tsafos has a diverse background in the private, public and non-profit sectors. He is currently a founding partner at enalytica. In his 7 ½ years with PFC Energy, Nikos advised the world’s largest oil and gas companies on some of their most complex and challenging projects; he also played a pivotal role in turning the firm into one of the top natural gas consultancies in the world, with responsibilities that included product design, business development, consulting oversight and research direction.
Prior to PFC Energy, Nikos was at the Center for Strategic and International Studies (CSIS) in Washington, DC where he covered political, economic, and military issues in the Gulf, focused on oil wealth, regime stability and foreign affairs. Before CSIS, he was in the Greek Air Force, and prior to his military service, Nikos worked on channeling investment from Greek ship-owners to Chinese shipyards.
Nikos has also written extensively on the domestic and international dimensions of the Greek debt crisis. His blog (Greek Default Watch) was listed as one of “Europe’s Top Economic Blogs” by the Social Europe Journal, and his book “Beyond Debt: The Greek Crisis in Context” was published in March 2013.
Nikos holds a BA with distinction in international relations and economics from Boston University and an MA with distinction in international relations from the Johns Hopkins School of Advanced International Studies (SAIS).
!52
Nikos Tsafos Partner
!!
enalytica
enalytica
Janak Mayer › Nikos Tsafos